Steam assisted gravity drainage (“SAGD”) is a process first proposed by R. M. Butler and later developed and tested at the Underground Test Facility (“UTF”) of the Alberta Oil Sands Technology and Research Authority (“AOSTRA”). The SAGD process was originally developed for use in heavy oil or bitumen containing reservoirs, (hereinafter collectively referred to as ‘heavy oil reservoirs’), such as the Athabasca oil sands. The process, as practised at the UTF, involved:                Drilling a pair of deviated wells having horizontal portions positioned close to and above the base of the reservoir containing the heavy oil. The horizontal portion of one well was located above the other in relatively close, generally co-extensive, vertically spaced apart and parallel relationship. The wells were spaced apart about 5–7 meters and extended in parallel horizontal relationship through several hundred meters of the oil pay or reservoir. The upper well was completed or equipped for steam injection. The lower well was completed for flowing production of heated oil and steam condensate. In summary, an associated pair of ‘horizontal wells’, suitable for the practice of SAGD, were provided;        Then establishing fluid communication between the wells so that fluid could move through the span of formation between them. This was achieved by circulating steam through each of the wells to produce a pair of “hot fingers”. The span between the wells warmed by conduction until the contained oil was sufficiently heated so that it could be driven by steam pressure from one well to the other. The viscous oil in the span was replaced with steam by injecting steam through the injection well and producing the oil from the span through the production well. The wells were then ready for SAGD operation;        Then converting to the practice of SAGD production. More particularly, the upper well was used to inject steam and the lower well was used to produce a product mixture of heated oil and condensed water. The production well was operated under steam trap control. That is, the production well was throttled to maintain the production temperature below the saturated steam temperature corresponding to the production pressure. Otherwise stated, the fluids being produced at the production interval should be at undersaturated or “subcooled” condition. (Subcool=steam temperature corresponding to the measured producing production pressure—measured temperature.) This was done to ensure a column of liquid over the production well, to minimize “short-circuiting” by injected steam into the production well. The injected steam began to form an upwardly enlarging steam chamber in the reservoir. The chamber extended along the length of the horizontal portions of the well pair. Oil that had originally filled the chamber sand was heated, to mobilize it, and drained, along with condensed water, down to the production well, through which they were removed. The chamber was thus filled with steam and was permeable to liquid flow. Newly injected steam rose through the chamber and supplied heat to its peripheral surface, thereby enlarging the chamber upwardly and outwardly as the oil was mobilized and drained, together with the condensed water, down to the production well.This process is described in greater detail in Canadian patent 1,304,287 (Edmunds, Haston and Cordell).        
The process was shown to be commercially viable and is now being tested by several oil companies in a significant number of pilot projects.
Now, the operation of a single pair of wells practising SAGD has a finite life. When the upwardly enlarging steam chamber reaches the overlying, cold overburden, it can no longer expand upwardly and heat begins to be lost to the overburden. If two well pairs are being operated side by side, their laterally expanding steam chambers will eventually contact along their side edges and further oil-producing lateral expansion comes to a halt as well. As a result, oil production rate begins to drop off. As a consequence of these two occurrences, the steam/oil ratio (“SOR”) begins to rise and continued SAGD operation with an associated well pair eventually becomes uneconomic.
If one considers two side-by-side SAGD well pairs which have been produced to “maturity”, as just described, it will be found that a ridge of unheated oil is left between the well pairs. It is, of course, desirable to ameliorate this loss of unrecovered oil.
In Canadian patent 2,015,460 (Kisman), assigned to the present assignee, there is described a technique for limiting the escape of steam into a thief zone. For example, if steam is being injected into a relatively undepleted reservoir section and there is a nearby more depleted reservoir section, forming a low pressure sink, there is a likelihood that pressurized steam will migrate from the undepleted section into the more depleted section—which is an undesired result. One wants to confine the steam to the relatively undepleted section where there is lots of oil to be heated, mobilized and produced. The Kisman patent teaches injecting a non-condensible gas, such as natural gas, into the more depleted section to raise its pressure and equalize it with the pressure in the relatively undepleted section. By this means, the loss of steam from the one section to the other can be curtailed or minimized. This is taught in the context of patterns of vertical wells.
The Kisman patent further teaches that pressurizing the more depleted section with natural gas has been characterized by an increase in production rate from that section, if the production well penetrating the section is produced during pressurization.